The determination of the location of a distant subterranean object may be of considerable commercial importance in the fields of well drilling, tunnel boring, pipeline laying under rivers or other surface obstructions, hard rock mining, and so on. In hydrocarbon extraction, a drill string may be 3 to 6 inches in diameter, and yet may extend many thousands of feet into the ground. Given the non-homogeneity of the underlying geological structure, and the tendency for drill bits to wander, it may be difficult to know with reasonable accuracy precisely where the drill bit may be. This issue may tend to have enhanced importance in the context of, for example, directional drilling, where it may be desired to follow a relatively narrow and possibly undulating geological feature, such as a coal seam, a hydrocarbon payzone for oil or gas extraction, an ore vein or pipe, such as a kimberlite pipe from which a mineral or other resource is to be extracted, or the boring of a utility conduit in an urban area.
There are known methods of addressing these issues, sometimes termed borehole telemetry. A typical system might involve magnetic sensors that indicate azimuth angle (i.e., compass direction relative to North) and angle of dip. Gyroscopic (i.e., inertial) and magnetic sensors have been used for some time. Adjustments in drilling may occur on the basis of these signals. It may also be noted that while borehole telemetry may pertain to the absolute position of a drill head, it may also refer to, and have significant commercial importance in relation to, the relative position of one bore hole to another, as in steam assisted gravity drainage (SAGD) or of bore position relative to a geological boundary structure. This problem is discussed in U.S. Pat. No. 7,084,782 of Davies et al., issued Aug. 1, 2006, generally from col. 1, line 16 to col. 5, line 17, and particularly at column 2, lines 3-53, all of which is incorporated herein by reference. Among other items, Davies at el., note that:
(a) The drilling operation, and mud motor life, may be optimized by the real time transmission of, and adjustment of drilling operations in response to, measurement data of natural gamma rays, borehole inclination, borehole pressure, resistivity of the formation and, mud motor bearing temperature, and weight on the bit.
(b) When used with a downhole motor, the mud pulse telemetry system is typically located above the mud motor so that it is spaced a substantial distance from the drilling bit to protect the electronic components from the effects of vibration. As a result, the measured environmental data may not necessary correlate with the actual conditions at the drilling bit. A conventional telemetry system may have a depth lag (i.e., a distance offset) of up to or greater than 60 feet. It is possible to drill out of a hydrocarbon producing formation before detecting the exit, resulting in the need to drill several meters of borehole to get back into the pay zone. The interval drilled outside of the pay zone results in lost production revenue and may include wasted costs for completing that non-producing interval.
(c) Near bit sensor systems have been developed to provide early detection of changes to the formation while drilling, but may still be located a spaced distance from the drill bit assembly, giving a lag in determination of formation changes. Mounting sensors in a mud motor may be very costly and may reduce system reliability.
(d) Systems permitting relatively high rate, bi-directional, data transmission have been developed for sending data to the surface through an electrical line. However, a drill string wireline or cable is subject to stress at pipe connections; may be prone to wear, damage or destruction during normal drilling operations; and may be somewhat unreliable and prone to failure.
(e) Systems have also been developed for the downhole generation and transmission of acoustic or seismic signals or waves through the drill string or surrounding formation. However, a relatively large amount of downhole power is typically required to generate sufficient signal strength for surface detection. A relatively large power source must be provided or repeaters can be used at intervals along the string to boost the signal as it propagates.
This problem is also discussed in U.S. Pat. No. 7,035,165 of Tang, at col. 1, line 35 to col. 2, line 5: “Recently, horizontal boreholes, extending several thousand meters (“extended reach” boreholes), have been drilled to access hydrocarbon reserves at reservoir flanks and to develop satellite fields from existing offshore platforms. Even more recently, attempts have been made to drill boreholes corresponding to three-dimensional borehole profiles. Such borehole profiles often include several bends and turns along the drill path. Such three dimensional borehole profiles allow hydrocarbon recovery from multiple formations and allow optimal placement of wellbores in geologically intricate formations.”
“Hydrocarbon recovery can be maximized by drilling the horizontal and complex wellbores along optimal locations within the hydrocarbon-producing formations (payzones). Crucial to the success of these wellbores is (1) to establish reliable stratigraphic position control while landing the wellbore into the target formation and (2) to properly navigate the drill bit through the formation during drilling. In order to achieve such wellbore profiles, it is important to determine the true location of the drill bit relative to the formation bed boundaries and boundaries between the various fluids, such as the oil, gas and water. Lack of such information can lead to severe “dogleg” paths along the borehole resulting from hole or drill path corrections to find or to reenter the payzones. Such wellbore profiles usually limit the horizontal reach and the final wellbore length exposed to the reservoir. Optimization of the borehole location within the formation can also have a substantial impact on maximizing production rates and minimizing gas and water coning problems. Steering efficiency and geological positioning are considered in the industry among the greatest limitations of the current drilling systems for drilling horizontal and complex wellbores. Availability of relatively precise three-dimensional subsurface seismic maps, location of the drilling assembly relative to the bed boundaries of the formation around the drilling assembly can greatly enhance the chances of drilling boreholes for maximum recovery. Prior art downhole lack in providing such information during drilling of the boreholes”.
“Modern directional drilling systems usually employ a drill string having a drill bit at the bottom that is rotated by a drill motor (commonly referred to as the “mud motor”). A plurality of sensors and MWD devices are placed in close proximity to the drill bit to measure certain drilling, borehole and formation evaluation parameters. Such parameters are then utilized to navigate the drill bit along a desired drill path. Typically, sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a formation resistivity measuring device are employed to determine the drill string and borehole-related parameters. The resistivity measurements are used to determine the presence of hydrocarbons against water around and/or a short distance in front of the drill bit. Resistivity measurements are most commonly utilized to navigate or “geosteer” the drill bit. However, the depth of investigation of the resistivity devices usually extends to 2-3 meters. Resistivity measurements do not provide bed boundary information relative to the downhole subassembly. Furthermore, error margin of the depth-measuring devices, usually deployed on the surface, is frequently greater than the depth of investigation of the resistivity devices. Thus, it is desirable to have a downhole system which can relatively accurately map the bed boundaries around the downhole subassembly so that the drill string may be steered to obtain optimal borehole trajectories.”
“Thus, the relative position uncertainty of the wellbore being drilled and the important near-wellbore bed boundary or contact is defined by the accuracy of the MWD directional survey tools and the formation dip uncertainty. MWD tools are deployed to measure the earth's gravity and magnetic field to determine the inclination and azimuth. Knowledge of the course and position of the wellbore depends entirely on these two angles. Under normal operating conditions, the inclination measurement accuracy is approximately plus or minus 0.2.degree. Such an error translates into a target location uncertainty of about 3.0 meters per 1000 meters along the borehole. Additionally, dip rate variations of several degrees are common. The optimal placement of the borehole is thus very difficult to obtain based on the currently available MWD measurements, particularly in thin pay zones, dipping formation and complex wellbore designs.”
Commentary on downhole telementry is provided in U.S. Pat. No. 6,781,521, of Gardner et al., which issued on Aug. 24, 2004 in the context of transmitting downhole data to the surface during measurement while drilling (MWD) (See col. 1, line 46 to col. 2, line 57), as follows: “Heretofore, in this field, a variety of communication and transmission techniques have been attempted to provide real time data from the vicinity of the bit to the surface during drilling. The utilization of MWD with real time data transmission provides substantial benefits during a drilling operation. For example, continuous monitoring of downhole conditions allows for an immediate response to potential well control problems and improves mud programs.”
“Measurement of parameters such as bit weight, torque, wear and bearing condition in real time provides for more efficient drilling operations. In fact, faster penetration rates, better trip planning, reduced equipment failures, fewer delays for directional surveys, and the elimination of a need to interrupt drilling for abnormal pressure detection is achievable using MWD techniques.”
“At present, there are four major categories of telemetry systems that have been used in an attempt to provide real time data from the vicinity of the drill bit to the surface; namely, mud pressure pulses, insulated conductors, acoustics and electromagnetic waves.”
“In a mud pressure pulse system, the resistance of mud flow through a drill string is modulated by means of a valve and control mechanism mounted in a special drill collar near the bit. This type of system typically transmits at 1 bit per second as the pressure pulse travels up the mud column at or near the velocity of sound in the mud. It is well known that mud pulse systems are intrinsically limited to a few bits per second due to attenuation and spreading of pulses.”
“Insulated conductors, or hard wire connection from the bit to the surface, is an alternative method for establishing downhole communications. This type of system is capable of a high data rate and two way communication is possible. It has been found, however, that this type of system requires a special drill pipe and special tool joint connectors which substantially increase the cost of a drilling operation. Also, these systems are prone to failure as a result of the abrasive conditions of the mud system and the wear caused by the rotation of the drill string.”
“Acoustic systems have provided a third alternative. Typically, an acoustic signal is generated near the bit and is transmitted through the drill pipe, mud column or the earth. It has been found, how ever, that the very low intensity of the signal which can be generated downhole, along with the acoustic noise generated by the drilling system, makes signal detection difficult. Reflective and refractive interference resulting from changing diameters and thread makeup at the tool joints compounds the signal attenuation problem for drill pipe transmission.”
“The fourth technique used to telemeter downhole data to the surface uses the transmission of electromagnetic waves through the earth. A current carrying downhole data signal is input to a toroid or collar positioned adjacent to the drill bit or input directly to the drill string. When a toroid is utilized, a primary winding, carrying the data for transmission, is wrapped around the toroid and a secondary is formed by the drill pipe. A receiver is connected to the ground at the surface where the electromagnetic data is picked up and recorded. It has been found, however, that in deep or noisy well applications, conventionals electromagnetic systems are unable to generate a signal with sufficient intensity to be recovered at the surface.”
“In general, the quality of an electromagnetic signal reaching the surface is measured in terms of signal to noise ratio. As the ratio drops, it becomes more difficult to recover or reconstruct the signal. While increasing the power of the transmitted signal is an obvious way of increasing the signal to noise ratio, this approach is limited by batteries suitable for the purpose and the desire to extend the time between battery replacements. It is also known to pass band filter received signals to remove noise out of the frequency band of the signal transmitter. These approaches have allowed development of commercial borehole electromagnetic telemetry systems which work at data rates of up to four bits per second and at depths of up to 4000 feet without repeaters in MWD applications. It would be desirable to transmit signals from deeper wells and with much higher data rates which will be required for logging while drilling, LWD, systems.”
The problem of transmitting encoded data by acoustic signals is also discussed in U.S. Pat. No. 6,614,360 of Leggett et al., issued Sep. 2, 2003, who suggest that much preliminary data processing may occur downhole (See col. 3, line 60 to col. 4, line 30):
“Wireline acoustic technology has been particularly difficult to adapt to MWD applications. In addition to road noise generated by the drilling assembly dragging against the wall of the borehole, there is an additional source of noise generated by the rotation of the drill bit and the drill string. Further, the slotted isolation sub technique used to isolate transmitters and receivers in wireline applications can not be used in MWD applications in that such slots would mechanically weaken the MWD acoustic subassembly to the failing point. In addition, the previously described full wave wireline acoustic measurement generates tremendous amounts of digital data. These data exceed the telemetry rates and storage capacities of current MWD systems thereby eliminating the option of processing full wave acoustic data at the surface. This problem is compounded when other types of sensors, comparable in sophistication to corresponding wireline applications, are run in combination with full wave acoustic devices. As an example, it is not feasible using current MWD telemetry capacity to transmit simultaneously a plurality of full acoustic wave forms or gamma ray energy spectra or electromagnetic wave attenuation and phase shift data, or a combination thereof, to the surface for processing to determine parameters of interest at depth intervals sufficient to obtain the required vertical resolution of the penetrated formations. The simultaneous transmission of drilling management sensor information such as directional information, weight on the drill bit, and other non formation evaluation type measurements still further overloads current MWD telemetry transmission rates which are of the order of 2 to 60 bits per second. Furthermore, it is not feasible to store copious amounts of raw data downhole sensor data for subsequent retrieval and processing due to relatively limited storage capacity of current MWD systems. Acoustic and other MWD methods for making multiple formation and borehole evaluation type parametric determinations comparable to current wireline measurements require the computation of the desired parameters downhole, and the transmission of the computed parameters of interest to the surface. By using downhole computational methods, the transmission requirements are reduced by orders of magnitude in that only “answers” are telemetered rather than raw data. This type of downhole computation is also applicable to other types of non formation evaluation type measurements such as signals indicative of the operational characteristics of the downhole equipment as well as measurements indicative of drilling direction and efficiency.”
In summary, the downhole environment may not be benign. It may be relatively hot. There may be abrasive and reactive fluids. Equipment used to drill rock may be subject to unhelpfully harsh shock and vibration spectra. Consequently, the use of electrical sensing and telecommunication equipment and electrical connections in a downhole environment may not always work well. Second, the sensing equipment may tend to be relatively fragile, and so may tend to be placed behind the mud motor in a coiled tubing system. The use of acoustic signal transmission is known, but so too are problems with acoustic attenuation, and with the rather limited data transmission rate. Further, it may be difficult to send acoustic signals in an acoustically noisy environment given the very significant noise generation of the bit itself.
The present inventor has taken a different approach.